赫斯 (HES) 2015 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the first-quarter 2015 Hess Corporation conference call. My name is Lisa and I will be your operator for today. At this time, all participants are in listen-only mode. Later we will conduct a question-and-answer session. (Operator Instructions) As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to Jay Wilson, Vice President of Investor Relations. Please proceed.

Thank you, Lisa. Good morning, everyone, and thank you for participating in our first-quarter earnings conference call. Our earnings release was issued this morning and appears on our website, www.Hess.com. Today's conference call contains projections and other forward-looking statements within the meaning of federal securities laws. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ from those expressed or implied in such statements. These risks include those set forth in the risk factors section of Hess's annual and quarterly reports filed with the SEC.

Also on today's conference call we may discuss certain non-GAAP financial measures. A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

With me today are John Hess, Chief Executive Officer; Greg Hill, Chief Operating Officer; and John Rielly, Chief Financial Officer. I will now turn the call over to John Hess.

Thank you, Jay. Welcome to our first-quarter conference call. I will provide some key highlights from the quarter and outline the steps we are taking to protect our financial strength in the current price environment while preserving our long-term growth options. Greg Hill will then discuss our operating performance, and John Rielly will review our financial results.

While low crude oil prices significantly impacted our first-quarter financial results, we delivered strong operating performance and production growth. In addition, we made considerable progress in our ongoing cost reduction efforts. In early February, we met with approximately 100 of our top service providers and suppliers to seek meaningful and sustainable cost reductions. While Greg will provide additional details, to date we have identified cost reductions of approximately $550 million with approximately $300 million resulting from a reduction in capital and exploratory expenditures and approximately $250 million from a reduction in cash operating costs.

As a result, we are revising down our forecast of 2015 capital and exploratory expenditures to $4.4 billion from our previous forecast of $4.7 billion with the balance of the cost savings, approximately $250 million, reducing our 2015 cash cost by $2 per barrel. While these cost savings will be dedicated to reducing our funding deficit, we will continue to proactively take steps to further strengthen our financial position.

Our Bakken rig count, which averaged 17 rigs in 2014 and 12 rigs in the first quarter of this year, currently stands at eight rigs and is expected to remain at this level for the balance of 2015. Following the laying down of two offshore rigs by the end of the second quarter, one in Norway and one in Equatorial Guinea, our capital and exploratory expenditures will approach an annualized run rate of approximately $3.8 billion, which is a reduction of about one-third from our 2014 spend.

With regard to our financial results, in the first quarter of 2015 we posted a net loss of $389 million. On an adjusted basis, the net loss was $279 million or $0.98 per share compared to net income of $1.38 per share for the year-ago quarter. Compared to the first quarter of 2014, our financial results were impacted by lower crude oil and natural gas selling prices and higher DD&A expense, which more than offset the impact of higher crude oil and natural gas sales volumes.

Net production in the first quarter averaged 361,000 barrels of oil equivalent per day. This represents an increase of 23% from pro-forma production of 294,000 barrels of oil equivalent per day in last year's first-quarter excluding Libya. This improvement was driven by higher production from the Bakken and the startup of the Tubular Bells Field, which commenced production in the fourth quarter of last year.

Net production from the Bakken averaged 108,000 barrels of oil equivalent per day in the first quarter, slightly above our guidance range. We have an advantaged acreage position in the Bakken with more drilling spacing units in the core of the play than any other company. With an eight-rig program at current prices and incorporating the announced cost savings, we have more than a seven-year inventory of drilling locations that can generate after-tax returns of 15% or higher.

Moreover, our Bakken team continues to drive our well costs lower. In the first quarter drilling and completion costs averaged $6.8 million, down 9% from the year-ago quarter. In addition, our wells continue to be more productive than the industry average.

In the Deepwater Gulf of Mexico, net production from our Tubular Bells Field, in which Hess has a 57% interest and is operator, averaged 18,000 barrels of oil equivalent per day in the quarter and is expected to be in the range of 30,000 to 35,000 barrels of oil equivalent per day for 2015. A third well commenced production in January and first oil from a fourth producer is expected in the second quarter of 2015.

We also continued to progress two Hess-operated developments in the quarter, the North Malay Basin project in the Gulf of Thailand, in which we have a 50% working interest, and the Stampede project in the deepwater Gulf of Mexico, in which we have a 25% working interest. First production is on track for North Malay Basin full field development in 2017 and Stampede in 2018.

During the quarter, we closed on the sale of Hess Corporation's interests in Hess Energy Trading Company or HETCO. We are also continuing to advance the midstream master limited partnership process to maximize value of our Bakken midstream assets. In March, Hess Midstream Partners filed a third amendment to its S-1 filing in preparation for an initial public offering. We look forward to providing you further updates in the near future.

In summary, we delivered strong operating results for the quarter and captured significant cost savings for the year with additional reductions being pursued. With our robust balance sheet, resilient portfolio and top-quartile operating capabilities, we are well-positioned for both the current price environment as well as for our future recovery in oil prices.

I will now turn the call over to Greg for an operational update.

Thanks, John. I'd like to provide an operational update and a review of the progress we are making in further reducing our cost base while continuing to execute our E&P strategy.

Starting with production, in the first quarter we averaged 361,000 net barrels of oil equivalent per day, substantially exceeding our first-quarter guidance of 330,000 to 340,000 barrels of oil equivalent per day and reflecting strong performance across our portfolio. Looking forward, our full-year 2015 net reduction forecast remains 350,000 to 360,000 barrels of oil equivalent per day excluding any production contribution from Libya. On the same basis, we forecast net production in the second quarter to average between 355,000 and 365,000 barrels of oil equivalent per day. As usual, we will update our full-year production guidance in our second-quarter conference call.

As John mentioned, during the first quarter we completed an extensive companywide review of our cost base. As a result, we have reduced our 2015 capital and exploratory budget by $300 million to $4.4 billion and reduced our 2015 cash operating costs by $250 million or approximately $2 per barrel of oil equivalent. Of the $550 million of initial savings we have identified, about $50 million comes from reduction in activity level, $250 million from what I will call self-help cost reductions, $250 million from supply chain savings.

The reduction in activity level is associated with a decision to reduce the Utica from a two-rig program to a one-rig program by June. The self-help productions are across the board and come from more than 1,000 different opportunities identified around the Company. The supply chain savings range from 10% to 30% with tubulars and other consumables being at the low end of that range and onshore pressure pumping and land rig day rates being towards the upper end of that range. We continue to identify additional cost reduction opportunities and will keep you appraised of further progress on future calls.

Turning to operations and beginning with unconventionals, in the first quarter our net production from the Bakken averaged 108,000 barrels of oil equivalent per day compared to 102,000 barrels of oil equivalent per day in the fourth quarter of 2014. We brought 70 new wells online in the first quarter compared to 96 wells in the fourth quarter of last year.

We reduced our Bakken rig count from an average of 12 in the first quarter to our current level of eight, where we expect to remain for the balance of the year. Over 2015, despite this reduced rig count, we still expect to drill 178 wells, complete 214 wells, and bring 213 new wells online due to increased drilling efficiency. This compares to last year, and we drilled 261 wells, completed 230 wells, and brought 238 wells online.

In the second quarter we forecast net Bakken production to average between 100,000 and 110,000 barrels of oil equivalent per day. Our full-year 2015 net Bakken production guidance remains at 95,000 to 105,000 barrels of oil equivalent per day.

Because of our core of the core position in the Bakken, we retain a substantial drilling inventory where economics remain attractive. By applying lean manufacturing practices to our operations, we continue to drive down our Bakken drilling and completion costs with the first quarter averaging $6.8 million per well versus $7.1 million in the fourth quarter and $7.5 million in year-ago quarter. The bulk of the savings to date are the result of applying our distinctive lean manufacturing capability.

Going forward, including the effect of further lean efficiency gains and service cost reductions, we are now targeting drilling and completion costs to average between $6 million and $6.5 million per well for full-year 2015. In line with this, we have reduced our Bakken capital budget to $1.7 billion for 2015, down from our previous guidance of $1.8 billion. Our top-quartile costs in combination with a high productivity of our wells allows us to continue to deliver some of the highest-return wells in the play.

As we mentioned on our last call and at our Investor Day last November, we have moved to 13 wells per DSU as our standard basis of development. On our four existing 17-well per DSU pilots, the majority of the wells are performing in line with type curves indicating minimal interference. We have therefore increased the total number of our 17-well per DSU pilots to nine in 2015.

Moving to the Utica, in the first quarter the joint venture drilled five wells, completed four wells, and brought four wells on production. Net production for the first quarter averaged 17,000 barrels of oil equivalent per day compared to 5,000 barrels of oil equivalent per day in the year-ago quarter and 13,000 barrels of oil equivalent in the fourth quarter of 2014.

Similar to our Bakken position, our Utica acreage is largely held by production, which allows us to reduce activity in the short term while preserving the long-term upside. Given the current pricing environment, the partnership has elected to focus activities on our Harrison County acreage, utilizing a single Hess-operated rig across the joint venture. Our revised budget for the Utica is $240 million for the year, down from $290 million. With this change, we now anticipate drilling 15 to 20 wells in 2015 versus our previous guidance of 20 to 25. Our expectation of bringing 25 to 30 new wells online in 2015 remains unchanged. In terms of net production, we still expect to average between 15,000 and 20,000 barrels of oil equivalent per day for the year.

Turning to the offshore, in the deepwater Gulf of Mexico we continue to increase production at our Tubular Bells Field, in which Hess holds a 57.1% working interest and is operator. Net production averaged 18,000 barrels of oil equivalent per day for the first quarter as we experienced some temporary constraints due to mechanical issues with the compressors which have now been rectified. Well deliverability from existing wells is encouraging and we expect the fourth producer to be online midyear. Our 2015 full-year forecast remains between 30,000 and 35,000 net barrels of oil equivalent per day.

In Norway at the BP-operated Valhall Field, in which Hess has a 64% interest, net production averaged 30,000 barrels of oil equivalent per day in the first quarter. Three producers were brought online and maintenance activities were successfully completed. We continue to expect full-year 2015 net production to be in the range of 30,000 to 35,000 barrels of oil equivalent per day.

In the Gulf of Thailand at North Malay Basin, in which Hess has a 50% working interest and is operator, first-quarter net production averaged 38 million cubic feet per day through the early production system and is expected to remain around 40 million cubic feet per day through 2016. In March, construction commenced on the jacket and topsides of the central processing platform, part of the full field development project, which is expected to increase net production to 165 million cubic feet per day in 2017.

In the deepwater Tano/Cape Three Points block in Ghana, in the first quarter the Guinean government approved the farm down of our license interest to Lukoil. Hess will retain a 40% interest and operatorship, and with our co-owners we continue to incorporate appraisal results into our subsurface models and progress engineering design work.

Moving to exploration, in Kurdistan, where Hess has a 64% interest and is operator, we and our partner Petroceltic have elected to relinquish the Dinarta license and withdraw from the region. All license obligations have been fulfilled other than the required final remediation of the well sites, which is underway.

In the Gulf of Mexico the Sicily well, in which Hess holds a 25% working interest, has reached final TD. Chevron, the operator, has completed logging and sidewall coring of the well and the results are currently under evaluation.

In Guyana, in March, the operator, Esso Exploration and Production Guyana limited, spud the offshore Liza 1 well and the Stabroek license, in which Hess holds a 30% interest. We expect to reach target depth by the end of the second quarter of this year.

In closing, in this quarter we have again demonstrated strong operational performance and made significant progress in reducing our cost base in a manner that positions us well to resume our strong growth trajectory when prices recover.

I will now turn the call over to John Rielly.

Thanks, Greg. In my remarks today I will compare results from the first quarter of 2015 to the fourth quarter of 2014. Our adjusted net loss, which excludes items affecting comparability of earnings between periods, was $279 million in the first quarter of 2015 compared with adjusted net income of $53 million in the fourth quarter of 2014. On an unadjusted basis the Corporation incurred a net loss of $389 million in the first quarter of 2015 compared with a net loss of $8 million in the fourth quarter of 2014.

Turning to exploration and production, the E&P net loss was $286 million in the first quarter of 2015 compared to net income of $92 million in the fourth quarter of 2014. The E&P adjusted loss was $193 million in the first quarter of 2015 compared to adjusted earnings of $147 million in the fourth quarter of 2014.

The changes in the after-tax components of adjusted results for E&P between the first quarter of 2015 and fourth quarter of 2014 were as follows. Lower realized selling prices decreased results by $363 million. Lower sales volumes decreased results by $31 million. Lower exploration expense increased results by $63 million. Lower cash operating costs increased results by $29 million. Higher DD&A expense decreased results by $52 million. All other items net to an increase in results of $14 million, for an overall decrease in first-quarter adjusted results of $340 million.

In February, we hedged 50,000 barrels per day of crude oil production from March 1 through the end of 2015 by entering into Brent crude collars with a floor price of $60 per barrel and a ceiling price of $80 per barrel. For the quarter our E&P operations were underlisted compared with production by approximately 1 million barrels, which had the effect of increasing our first quarter after-tax loss by approximately $7 million.

The E&P effective income tax rate, excluding items affecting comparability, was a benefit of 50% for the first quarter of 2015, which was favorable to our guidance of 40% to 44%, due primarily to the mix of income generated by operations during the quarter. The E&P effective tax rate in the fourth quarter of 2014 was 41%, excluding the effect of Libya operations.

Turning to corporate, corporate and interest expenses after income taxes were $90 million in the first quarter of 2015 compared to $97 million in the fourth quarter of 2014. The decreased costs in the first quarter were a result of lower professional fees and other costs.

Turning to cash flow, net cash provided by operating activities in the first quarter, including a decrease of $108 million from changes in working capital, was $362 million. Net proceeds from asset sales were $95 million. Capital expenditures were $1.237 billion. Common stock acquired and retired amounted to $67 million. Repayments of debt were $17 million. Common stock dividends paid were $72 million. All other items amounted to a decrease in cash of $2 million, resulting in a net decrease in cash and cash equivalents in the first quarter of $938 million.

Turning to our stock repurchase program, in the first quarter we substantially reduced purchases of our common stock. The total program-to-date purchases total 62.9 million shares at a cost of approximately $5.3 billion.

Turning to our financial position, we had $1.5 billion of cash and cash equivalents at March 31, 2015, compared with $2.4 billion at December 31, 2014. Total debt was approximately $6 billion at both March 31, 2015, and December 31, 2014. The Corporation's debt-to-capitalization ratio of March 31, 2015, was 21.6% compared to 21.2% at the end of 2014.

We have a strong balance sheet and liquidity position to manage through this low commodity price cycle. Our capital spending will continue to decrease with the reduction of rigs in North Dakota, Norway, and Equatorial Guinea and as result of our ongoing cost reduction efforts. This will allow us to achieve an annualized run rate of capital spend that is about one-third less than our actual 2014 capital and exploratory expenditures and at the same time preserve our operating capabilities to position us well for a recovery in oil prices.

Turning to guidance, as a result of the progress we have made in the initial phase of our cost reduction efforts, I would like to provide updated guidance for certain second-quarter and full-year 2015 metrics. For the second quarter and full year of 2015, cash costs are expected to be in the range of $17.50 to $18.50 per barrel, which is $2 per barrel lower than our original full-year guidance of $19.50 to $20.50 per barrel.

Depreciation, depletion, and amortization guidance for the second quarter and full-year is unchanged and is expected to be in the range of $28.50 to $29.50 per barrel, resulting in total production unit costs of $46 to $48 per barrel.

Exploration expenses excluding dry hole costs are expected to be in the range of $90 million to $100 million in the second quarter and reduced by $20 million to $380 million to $400 million for the full year 2015.

The E&P effective tax rate excluding items affecting comparability is expected to be a benefit in the range of 39% to 43% excluding Libyan operations for the second quarter and for the full year.

For the second quarter of 2015 corporate expenses are estimated to be in the range of $30 million to $35 million net of taxes and interest expenses are estimated to be in the range of $50 million to $55 million net of taxes. The full-year 2015 guidance for corporate expenses of $120 million to $130 million net of taxes and interest expenses of $205 million to $215 million net of taxes, remains unchanged.

This concludes my remarks. We will be happy to answer any questions. I will now turn the call over to the operator.

(Operator Instructions) Guy Baber with Simmons.

Congrats on a strong quarter. First off, you mentioned you are continuing to pursue cost reductions. So could you just talk to us a little bit, based on your discussions with service providers and your evaluation of your operations, where you believe you are on the cost reduction front? Are there more significant cost reductions to come? And if you could just talk about it in the components that you broke it into a little bit earlier and what type of opportunities you foresee going forward and then how that could influence activity plans over the back half of the year and into next year, I would appreciate it. And then I have a follow-up.

Yes. I think, as I said in my opening remarks, really supply chain savings are across the board and they range all the way from 10% to 30%. With the 10%, the lower end of the range, being the consumables like steel because the steel on a worldwide basis is a pretty still strong market. On the upper end of that range you have your pumping services and your onshore rig rates towards that 30% range.

Discussions are ongoing with suppliers. It's hard for me to give you an estimate of where we are in the process. It's an ongoing process. We do expect additional cost reductions throughout the year, but it's too early to speculate on how much they will be or how much fast they will come.

Okay, great. And then I have a follow-up on cash flow. Could you just -- I appreciate you giving us the working capital numbers. Could you just talk a little bit more about that working capital component, how you expect that to evolve through the course of the year as you reduce your activity levels? I imagine that could influence your payables to a certain degree. And then is there anything else on the cash flow front that we need to be aware of that could influence cash flow or influence cash flow during 1Q in future quarters? And I'm thinking the deferred tax element or anything else that you might point out that's not visible to us in this environment.

Sure. So in the first quarter, as you saw, it was just over a $100 million decrease due to working capital. Now, there's ins and outs, as you can imagine, that's going to go through the portfolio every quarter. And in general from a guidance standpoint, we will have a pool on working capital as we go through the year. And that is due to our dismantlement efforts in the UK and in Norway. So if you saw in our 10-K in our current liabilities for dismantlement, we have $440 million of dismantlement costs that were expected liabilities to be incurred this year. So effectively, that $100 million that we have there results from that dismantlement.

On an ongoing basis, I would say with working capital it will generally be around the same amounts, except the second quarter will be slightly higher pools because we have tax payments internationally and then the third and fourth quarters being a bit lower. So that's in general working capital. There is not unusual I would tell you to expect then from our cash flow numbers.

As it relates to deferred taxes, the guidance that we have been giving out is that the benefit that we are providing as estimates and that you put in your models -- you should assume that tax benefit is a deferred benefit. And in the first quarter the actual benefit that we recorded was essentially all a deferred benefit. We do have some current taxes that we pay, but we also have some offsets from those dismantlement costs that I just mentioned. As we pay them in the UK, we receive some cash refunds.

That's very helpful. Thanks for the comments.

Doug Leggate with Bank of America.

I've got a couple also, if I may. Mr. Hess, I wonder if I could start with you. I just want to get some clarity on your comments around the midstream MLP process. Are you basically -- are you saying that the process does not have a timeline because of the need for commentary from the SEC and so on? Or are you shelving the process? What are you trying to signal to us by that comment?

Doug, there's no signal from that comment, just progression. And where we are -- as you know, we are in a quiet period in the registration process and we are limited really and what we can do and discuss about our midstream assets. We really can't provide any further comments on the process.

But there's no change from our understanding as to how things were or your appetite to get this done, I guess? Is that fair?

No, no, not at all, Doug. We are moving forward with the process.

Great, that's what I was looking for. Thank you. My follow-up is probably for Greg or maybe for whichever one of you guys wants to take this. But the way I've always thought about a lower oil price environment is that the best returns come from investing in the base where you have already got facilities and so on. So I guess what I'm trying to understand this when I look at the Africa volumes this quarter, they are obviously pretty strong compared to the guidance you suggested at the Analyst Day. So I'm curious. What are you doing to the base in this environment? If things stayed depressed for longer, would that get more to the incremental capital? I'm just trying to understand how you are thinking about managing through this over the next year or so. And I'll leave it at that. Thank you.

Sure, Doug. Under these prices -- and you are absolutely right; anything that we can invest around our existing hubs are the most profitable investments that we can make in the portfolio. Now, we always say we have a tension because we want to maintain that strong financial position. So, as you know, we did reduce rigs in North Dakota, and we are dropping the rig in EG in the middle of the year and we're stacking the Valhall platform rig in the middle of the year.

All of those opportunities are good-return opportunities. But again, we are balancing that with maintaining a strong financial position still while preserving growth options and preserving our operating capabilities. But having said that, from an incremental capital, we are really not looking at incremental capital right now in this price environment. But the first dollars, you are right, will for the most part go to where we have existing infrastructure because that will be our best returns.

All right, I'll leave it there. Thanks.

Doug Terreson with Evercore.

John, you've been a leader for the industry on some of these important energy policy issues inclusive of your recent comments in the Wall Street Journal. And on this point, while it seems that full removal of export ban may not be that likely this year, it does seem like there's some bipartisan momentum for swaps with Mexico. So I wanted to see if we could get your updated views on the potential outcomes here and timing and impacts or just any other thoughts you might have in this area.

Happy to do so. Obviously, it's political, Doug, as you mentioned. All we are trying to do is make sure our voice is heard and keep the pressure on, on this important issue. It will either take an act of Congress or an executive order from the President to give the green light to crude exports. It's a time where we are, as a country, considering lifting the sanctions on Iranian crude oil exports. Well, it's high time that we lift the sanctions on the self-imposed US crude imports. And so, we're trying to have our voice heard. Other members of the industry are. And I think we are trying to build and educate awareness with political leaders both on the congressional side as well as the executive branch to move this forward. So we are going to do what we can to make this more a current item as opposed to one that gets kicked down the road.

Okay. And then also there has been a lot of commentary on strategies for drilled but uncompleted wells in the United States. So my question is whether or not you could provide your view as to the opportunity for the industry and for the Company and just help us sort this out for Hess and whether or not it's meaningful or what have you.

Yes. Thanks, Doug. I can't speak for others. I think our philosophy is just from a return standpoint it doesn't make a lot of sense to drill a well but not complete it. And so, the decision should be to not drill a well upfront. And that's why we've collapsed to our core and said things outside the core we will save for a later day. But our philosophy is, where we have the good returns in the core of the core, we're going to drill and complete those wells in just the normal cycle, particularly with lean manufacturing, because you want to keep that learning and continuous improvement machine going because if you stop it and then restart it, say a year or two later, your startup cost will be more than if you just would have continued.

Great. Thanks a lot, guys.

David Heikkinen with Heikkinen Energy Advisors.

When we met earlier in the year you talk some about just the A&D market and just relatively widespread. And I think your comments around incremental capital might fit into that as well. How are you thinking about that opportunity set of pain in the industry and opportunity to add to your resource potential?

Right. We have plenty of great investment opportunities to create value for our shareholders from our current portfolio of assets and prospects. So as a consequence, that's where our focus is going to be to deliver future value.

Having said that, in the current environment if there are opportunities out there, and we are always looking, to strengthen our portfolio strategically that meet our investment thresholds and that don't sacrifice our balance sheet strength, things that would meet that, which we certainly haven't seen yet, then we would give that strong consideration. But the key in all this is to maintain our balance sheet strength. And also in all this we will be capital disciplined.

And then on the balance sheet with the cash pull-down through the year, have you any thoughts or update with the hedges in and where you would end the year on a cash balance?

So you can see we still have $1.5 billion in cash in the balance sheet. And just in general we have moderate leverage metrics and we have an undrawn $4 billion, a $4 billion revolver which doesn't mature until 2020. So we have ample liquidity. And as you mentioned, we've got the $550 million cost savings initiatives that we have already achieved. And we are continuing to work to drive further cost reductions throughout our portfolio. So that and also there has been some firming with the oil prices is helping to reduce our deficit. So I don't want to predict where we will be at the end of the year, but we believe we have the financial strength to fund any near-term deficit. That's why we keep that strong financial position.

Okay, worth a shot. Thanks, guys.

Jeffrey Campbell with Tuohy Brothers Investment Research.

My first question will be an operational one. In the Utica Shale are you concentrating on Harrison County because of the well quality, or is there some other reason?

The reason we're concentrating on Harrison County is that it's the core of the core of the wet gas play. So that offers the best returns.

And there has been a lot of discussion about re-fracking recently. I was just wondering, is that anything that you guys are experimenting with currently or thinking about?

Yes. We have done a fair number of re-fracks in the past, particularly we experimented a lot with them in 2010 timeframe. The results were very mixed. Having said that, I think we will continue to watch others and see how that develops. And if it looks like it's a value-accretive thing to do, we would do that. I would say if you can get your well costs down very low, it may make more sense just to re-drill a lateral then deal with the complexity of re-fracturing.

Great. Thank you.

Ryan Todd with Deutsche Bank.

Maybe one quick question on the Bakken -- production in the Bakken has pretty consistently exceeded expectation in recent quarters. And I was wondering if you could give any help in terms of generally what you think has been driving that. Have you had -- is it better than expected well performance? Are you seeing anything on the efficiency gains front going forward that we should consider? And then as we look at full-year guidance, you obviously started the year off above the guidance range. And I realize you don't update numbers until first half. But should we think about potential for upside to full-year numbers or how should we think about the trajectory from here over the course of the year?

Well, I think, again, we have reduced our rig count to eight. And so there is some uncertainty as to how or if the Bakken rolls. Now, we believe we can maintain production relatively flat with an eight-rig program, but obviously there's uncertainty in that. As the year develops and as we get more production experience, we will update our guidance accordingly.

Regarding performance being a little better than expected, we are seeing some very good type curve performance in the core of the core. And so, that has been a nice surprise for us.

Great, thanks. And then maybe if I could, one follow-up on infrastructure, you are spending $350 million on infrastructure this year. How should we think about the run rate from 2016 forward? Does that number come down? And over the long-term, is there the potential for that to eventually be shifted to the MLP?

So just before I discuss the MLP, the infrastructure costs this year are higher. We have some significant infrastructure work that we're doing south of the river to be able to bring hydrocarbons backup north of the river, either oil to our rail facility or gas to our gas plant. So we do have a higher infrastructure spend this year, and it will decrease as it goes forward to 2016. There always will be infrastructure spend. And then, yes, as the MLP is out in the market and is operating, they will be picking up the infrastructure spend.

Great, I appreciate it. Thanks.

Brian Singer with Goldman Sachs.

You've talked a lot about lower cost, particularly as it relates to the onshore. I wondered if you could give us an update on offshore costs including in areas like Stampede and North Malay, projects that are already on track, but whether you are seeing any cost deflationary pressures there.

Yes. I think the current environment provides some opportunities to capture cost reductions which will benefit Stampede before it comes on stream in 2018. So we are about 85% contracted through the first quarter of 2015. Now, I will remind you that 60% of the costs associated with drilling -- is associated with drilling and completions on Stampede and that in late 2014 we contracted seven string years with Diamond at a day rate of about $400,000, which is roughly 40% to 50% lower than what the 2013 market rates were. So we captured some of those savings already.

I think as just the general statement -- the cost savings in the offshore are not as deep and pronounced as the onshore, for obvious reasons. And they are coming at a slower pace than the ones in the onshore. They will come with time, particularly if crude prices stay low, but not at the rate or the depth that we are seeing in the onshore.

Great, thanks. And I wanted to follow up a bit on I think it was Doug Leggate's earlier question with regard to how we think about activity levels relative to cost structure and prices. You've talked a lot here about strong productivity trends, great Bakken acreage position, well costs that look like they will go sometime this year to $6 million. If you were to bring activity back on, do you think that those cost savings that you are seeing here are just going to completely reverse? Or do you see some of that lingering? And given these trends, how do you think about when it makes sense to stop subtracting activity and start adding activity?

Let me address what is an industry question, which is the ramp backup. A couple comments -- I think that the ramp-up will not be as fast as the ramp down. Why? Because there is a significant amount of workforce that has left the oil and gas industry. And so to restart those rigs and get crews and get all the people you need, that's going to be a much slower ramp. So I think as an industry our ability to ramp up will not be as fast as maybe some people anticipate. So I think that's the first context we will comment.

I think the other thing that we are thinking about -- John can build on this -- is we will have to see a fairly strong price signal for an extended period of time before we are just going to ramp activity backup. So any of those savings will, by definition, go straight back on to the balance sheet to help reduce our deficit.

Got it. And do you see the cost rising back to $7 million if and when activity levels start to tick back up?

I believe some of it's sustainable. But trying to predict when it will bounce back, how fast, I think is really difficult.

Thank you.

Paul Cheng with Barclays.

Greg, when we are looking at your first-half production including the first-quarter and the second-quarter guidance and your full year, should we look at it as you just being a little bit conservative or that you do expect during the summer to have a significant maintenance downtime in North Sea or some other areas and also that the cut in CapEx is really going to start taking the toll in some of the production including Bakken, that's why you are still more comfortable sticking to the full-year guidance?

Yes. Again, Paul, I think we only have one quarter under our belt. And we will update guidance, as we always do, at the end of the second quarter. We do have the usual maintenance in the summer months in our offshore fleet. We also have to tie in the new well at Tubular Bells and tie in a nearby accumulation called Gunflint that will also be brought into the Tubular Bells Williams facility. And so there's a little more downtime with Tubular Bells. I think, as I mentioned earlier, the uncertainty in the Bakken as you reduce the rig rates -- production is strong, it's going well. But as you reduce those rates, I think there are still some uncertainties. So I'd like to see a little more visibility on how the Bakken is going to behave before we update our guidance. But production has been strong, so far.

Greg, can I ask in a slightly different way? If we look at your maintenance activities for this year during the summertime and/or that second half, is it going to be about average of the previous year of the last couple of years? Or is it going to be significantly higher?

I think, just to give you some round numbers, we have about 25 days of maintenance for T Bells, which is a little high because we have these tie-ins that we're going to do. So that would be abnormal, I would say. 17 days for all the other Gulf of Mexico fields, so that's about normal. Six days on Valhall, again about normal. And then 17 days on JDA, which is a little higher because we are tying in booster compression and other things at JDA. So T Bells and JDA a little bit higher than normal.

Okay, perfect. And then maybe looking at the CapEx, when earlier you said that you can bring it down, I think, to $3.8 billion, the CapEx one way by towards the end of the year, is that the kind of run rate you need to sustain the production flat and the oil and gas mix steady?

The way we look at it Paul -- it's always a difficult question. The way we look at a run rate spend from keeping production flat is we look at it really keeping our barrels, our proved reserves barrels flat. So if you are talking about with 360,000 barrels a day, of approximate, of production, taking that by 365, you are saying you need to replace about 140-ish type million barrels and then take an F&D cost, $20 to $25. That's how we look at a capital spend just to keep reserves flat, which would imply over time that you can keep production flat. So that $3.8 billion would be in that range.

I see. Okay, very good. Thank you.

Evan Calio with Morgan Stanley.

A lot covered here. A follow-up on the Bakken inventory -- I know you provided the inventory and return calculations for your core of the core in the Bakken, the 15% return at 40 with seven years of depth. But are those wells closer to 800,000 BOEs at EUR or your base type curve at [660]? Or any other performance color on the expected type curves?

I think, Evan, as we've said, we've guided that [550] to [650] range on EUR. Obviously, as we collapse to the core, that number is going to increase over time, as will the IP rates as you begin to collapse to the core of the core. So yes, they will be a little bit stronger than what our average has been in the past.

And you can see some of that in the state data today. But that doesn't have other implications on the balance of the inventory? The balance of the inventory is still towards the average of type curve? Is that fair?

You mean outside the core?

Correct, yes.

(Multiple speakers) obviously within that range it would be at the lower end of that range for outside the core. So we're going to concentrate on the upper end of that range in our drilling program.

Great. And a follow-up -- I know during the Investor Day you talked about stage density being the greatest lever you can pull to improve IPs and EURs. Could you discuss your program with 50 stages per lateral and timing and any update on your 9-8 per DSU pilots, downspacing pilots?

Yes, you bet. So let me start with the 9-8. The results that we've seen from the four pilots are encouraging. And so, we are increasing the number of pilots on the 9 and 8 to nine this year. So again, some encouragement there. The 50 stage -- we've got a few under our belt. So operationally, they have gone extremely well. And now, we are just watching the production curves. And it's too early to say it's a victory or not. But so far, operationally, we have proven that we can get those in the ground without any trouble.

Great. Thanks, guys.

Edward Westlake with Credit Suisse.

So sticking with the Bakken, so outside of the core maybe any color on whether, either through getting more stages per well and therefore basically getting capital efficiency on the cost side or new technology, are you seeing any of the non-core acreage move up in terms of the breakevens, maybe a bit of a color about the breakevens that you see as you move outside of the core?

Yes. I think, obviously, as we get our well costs down and also get our productivity up potentially through a higher stage count, more of the inventory will come into that breakeven. Right? As I said before, though, I think increasing activity -- we are going to want pretty good price signals before we just go increase activity. So any savings is going to be swept to the balance sheet to help reduce our deficit in the near-term.

And then in terms of the 50 stage wells that you have under your belts, I don't know if we've seen production performance from them so far. Well, any idea where they are so that we can track them ourselves would be one question. But where did the well costs come in, in terms of relative to the average cost? Because I know you have been able to increase the stages and maintain relatively low well cost at the same time.

Yes, we are confident that we can stay well within our well cost even at 50 stages because of the improvements we're making not only through lean but through supply chain. Early days on the type curves, encouraging but we want to see good type curve history before we make a final decision on whether we move to 50 stage. So our standard design still remains 35, for now.

Right, and then a very small question on the gassy NGL mix in the Bakken. It seems to be increasing a little bit. That's just flaring rules, presumably, rather than any change in the geology?

Yes, no change in the geology. It's actually even just more hookups getting to our gas plant, which was being expanded. So just getting infrastructure and getting more of the gas into the plant.

Thanks very much.

Paul Sankey with Wolfe.

Thanks for all the new information you have given us. If I could just try and triangulate what I've heard, you said that the current run rate for CapEx is around $3.8 billion. And you separately said that you thought that that would be able to sustain flat reserves or 100% reserves replacement, which would imply flat volumes going forward over time. At the same time, separately again, I see that you have hedged at about $60 a barrel as a floor. And then finally, what you said is that you wouldn't simply re-raise your CapEx when oil prices recover, that it would be a lag effect.

So if I could pull it -- I hope I've got all that right. If I could just ask a couple of follow-up questions, are you now basically planning the Company at $60 a barrel with a name to keep volumes flat, first, until oil prices recover?

And second, within the plan you have also mentioned again separately that Bakken efficiency continues to improve. Would that $60 a barrel level imply that you would have rising Bakken volumes offsetting falling international volumes? Thanks.

Thanks, Paul. Just on an overall basis, I just want to remind that we remain committed to managing our business to be cash generative over the long-term. So you have summarized all our comments today correctly. It's not, per se, that we are absolutely planning at $60. But we are looking at the reality of where the current price environment is. And we want to make sure that we can be cash generative over the long-term.

So first, we are serious about addressing the funding deficit because we want to maintain our strong financial position. And that's why we started with the $550 million of cost savings, just to get to that $3.8 billion. So the first quarter was the peak of our capital spending. And spending will reduce each quarter throughout the year. And so that's why, by the second half of the year, we have this $3.8 billion run rate, which is about a third lower.

Now, general comments of being able to hold reserves -- again, you are talking about a $25 F&D. Obviously, if you just hold your reserves flat and you do increase production, you do reduce your reserve life. So we have the balance and we want to maintain the longevity of the portfolio as well. But we are focused right now on cost reduction efforts and reducing that funding deficit. And because we have a strong financial position, we can invest in this low commodity price cycle. So again, we are very focused on investing in the good returns in our portfolio. We want to maintain our growth options, and it's key that we preserve this top-quartile operating capability that we've developed.

And so that's why being able to keep the strong financial position to fund in any given year a deficit, but over the long-term -- just want to reemphasize that we will do what it takes to be cash generative over the long-term. So again, not focus on any individual price at one point in time, but that's how we are running the business.

Yes, I totally understand that. It just seems that $60 is the implicit number, let's say, for now, given what you see. Could you comment on the Bakken growth? Do you anticipate you can grow at $60?

Well, I think, again, as I said earlier, Paul, I think at eight rigs we believe we can hold the Bakken broadly flat within the range that we've guided. Now, we will see. There's some uncertainty in the number but we believe we can hold it broadly flat with eight rigs.

And eight corresponds to the current price environment that we are in right now, Paul. So that gives you a feel for at this price environment within eight-rig complement, we think we can keep the Bakken flattish for the next several years.

I've got it. And just finally I assume that within that you would be -- first of all, could I just confirm about what cash flow you would expect, let's say at $60 a barrel, given the noise that we had in Q1? And secondly, that I assume you continue to plan to raise the dividend over time. And I'll leave it there.

Paul, we can't -- just to estimate what's going to happen with prices -- so first of all, even at $60 we've got to focus then on the cost reduction efforts. And as Greg said, things will be coming over time. So trying to forecast exactly what our cash flow would be with $60 long-term would be difficult to do. So I think I just want to come back to that we are committed over the long-term to be cash generative over a cycle time. So that's how we are focusing the business.

Yes, and in terms of the cash dividend, right now our priority is the funding deficit and getting ourselves to a cash generative position. So those are the priorities right now -- and investing for returns.

Thank you very much indeed.

Pavel Molchanov with Raymond James.

You alluded to the fact that you would be potentially open to acreage acquisitions if something useful came along. Would you be equally open to some additional asset monetizations above and beyond all you've done in the past few years?

We've done, obviously, $13 billion worth of asset sales for the past couple of years, and -- to get our portfolio to a position that we really think it's competitive at low prices and it's going to be very competitive at high prices. So right now, obviously where prices are it's not a seller's market. We are focused absolutely on day in and day out, on cost reduction efforts and reducing our deficit. So that's our focus right now, Pavel.

And as always -- and we've said this before, but just to give clarity -- portfolio optimization is ongoing and part of the normal course of business as we move forward. And that includes the monetization of our Bakken midstream.

Okay. Can I also ask about hedging? Right now as we are talking the spread between the front month WTI contract and one year out is $6, $7. Are you taking advantage of the contango to layer in hedges for 2016 or even 2017?

No. The hedges we have on are what I mentioned in my earlier results. So we had 50,000 barrels a day of collars, and they are Brent collars, between $60 and $80. Again, we will continue to look at our price exposure on an annual basis, and we may hedge to provide some insurance. So in the first quarter we saw an opportunity to hedge against a pretty softening market right there and potential declines in 2015. And so we entered into those collars. But again, it's an ongoing thing that we may do. But at this point in time, it's the program that I mentioned.

All right. Appreciate it, guys. Thanks.

Thank you very much. This concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.